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Transcript
Power System
Engineering, Inc.
Distributed Generation Testing &
Commissioning
IEEE Rural Electric Power Conference
Jeff M. Triplett, P.E.
[email protected]
May 2014
Fort Worth, TX
Typical Interconnection Process
• Application
• Preliminary Review
• Screening Process
• Engineering Studies (as needed)
• Study Results and Construction Estimates
• Final Go – No Go Decision
• Design
• Order Equipment and Construction
• Inspection, Testing & Commissioning
2
Common Testing & Commissioning Questions
• What is required?
• Who is responsible for what?
• What is the process?
• What documentation needs to be provided and
maintained?
• What about ongoing requirements after initial
installation?
Responsibilities and requirements of both the interconnecting
customer and the utility need to be clearly established in the
interconnection policies and agreements.
3
Inspection and Testing
Inspection and testing of DG equipment and its associated
interconnection system is important for safety and system
reliability. Applicable standards and codes should be
referenced when developing or adopting procedures.






IEEE 1547
IEEE 1547.1
UL 1741
ANSI
NEC
NESC
4
IEEE 1547.1
IEEE Standard Conformance Test Procedures for
Equipment Interconnecting Distributed Resources
with Electric Power Systems
Specifies, in detail, the type of
production tests and field
commissioning tests needed to
demonstrate that a DG
installation conforms with
IEEE 1547.
5
Pre-Certification

Provides certification that a DG
package has been tested and listed by
a nationally recognized testing and
certification laboratory (NRTL) for
compliance with applicable codes and
standards.

Certification means that factory
testing yields plug and play systems
that only require limited field testing.

If only the interfacing components are certified, then the DG
owner needs to show that the generator is compatible with the
certified interfacing components and the parameters in which
they were tested.
6
UL 1741
UL 1741 is an industry accepted standard for inverters,
converters, controllers, and interconnection systems for use in
independent power systems.

For utility-interactive equipment.

Intended to supplement and be
used in conjunction with IEEE
1547

Intended to be installed in
accordance with the NEC.

Does not apply to induction or
synchronous generators.
7
Level of Testing Required
• Size and type of DG facility will be the primary
drivers that determine the testing and commissioning
requirements
• Smaller and/or pre-certified systems will require less
testing be done in the field
• Synchronous machines (because of their complex
controls) will require more extensive testing and
commissioning
Note that the terms “larger” and “smaller” used here are
relative terms generally referring to the size of the
generation capacity compared to the load in the area.
8
Smaller Inverter-Based Systems
Field Verification
1. Verify local inspector requirements have been met
2. Verify what has been installed in the field matches
application information
3. Verify AC disconnect installation and operation
according to utility requirements
4. Verify programmed inverter voltage/frequency trip
points and times
9
Smaller Inverter-Based Systems
Field Testing
1. Record time for inverter to begin outputting power
after normal AC voltage is established to the inverter
2. Measure and record voltages/amperages at relevant
locations with and without the inverter operating
3. Conduct a “cease-to-energize” test to verify inverter
stops outputting power when utility source lost
4. If inverter is not UL 1741 listed, may wish to do
additional testing (harmonics, DC current injection,
trip times, etc.)
10
Disclaimer
Adding a disclaimer to any utility test documentation is
recommended.
“Utility’s observation, review, inspection or testing
shall be construed neither as an endorsement or
confirmation of any aspect, feature, element or
condition of the Generation Facility or Interconnection
Customer’s protective equipment or the operation
thereof, nor as a warranty as to the fitness, safety,
desirability or reliability of same.”
11
Larger (Non-Inverter) Systems
12
Field Verification – Prior to Energization
Inspection
1. Verify local inspector requirements have been met
2. Verify what has been installed in the field matches
supplied documentation
3. Obtain/Verify from Interconnection Customer
a. Final as-built diagrams
b. Programmed relay settings
c. Test reports – CTs, VTs, relays, batteries, etc.
13
Field Verification – Prior to Energization
Instrument Transformers
Current transformers (CTs) and
voltage transformers (VTs)
used for monitoring and
protection should be tested for
correct polarity, ratio and
wiring.
CTs should be visually
inspected to confirm that all
grounding and shorting
connections have been
removed where required.
14
Field Verification – Prior to Energization
Trip Checks / Functional Testing
Protective relaying should be functionally tested
for correct operation of the complete system.
Functional testing requires that the complete
system be operated by the injection of current
and/or voltage to trigger the relay element causing
breaker tripping and lockout or provides the correct
signal to the next protective device.
NOTE: Utility should reserve the opportunity (but
not be required) to witness functional testing of
customer interconnection protection schemes.
15
Field Testing – Prior to Paralleling
• The following testing/commissioning is
recommended (as applicable) PRIOR to allowing the
generation to parallel with the utility system
– Phasing Test
– Synchronizing Test
16
Field Testing – Prior to Paralleling
Phase Tests
For three phase applications, phase rotation
between the DG facility wiring and distribution
system should be tested and verified.
Voltage
0
270
90
360
Time
A
180
B
C
17
Field Testing – Prior to Paralleling
Synchronization Test
This test should be performed on the DG paralleling
device and any other switching device that can parallel
the DG Facility output with the utility system. The test
should demonstrate that at the moment of the intended
paralleling-device closure, the frequency, voltage and
phase angle are within the required ranges stated in
IEEE 1547 as well as the manufacturer’s specifications.
The test should also demonstrate that if any of the
parameters are outside of the ranges stated; the
paralleling device will not close.
18
Field Testing – After Paralleling
Load Test
This test should be performed to verify correct polarity,
phasing and magnitudes of all instrument transformer
circuit inputs into relays, meters, etc.
19
Field Testing – After Paralleling
Anti-Islanding Test
This test should
demonstrate that the
DG facility will cease
to energize or isolate
itself from the utility
system within 2
seconds of the utility
source being removed.
*Source: IEEE P1527.2/D11
20
Possible Ongoing Testing
Power Quality Testing
Depending on the type of generation, it may be
desirable to verify over time that the generation is
not a source of objectionable levels of harmonics or
otherwise has a negative effect on power quality
such as being a source of voltage transients or
fluctuations.
Examples: Large wind or solar installations
21
Utility Testing
• It is not uncommon for specific utility protection
schemes to be needed to safely and reliably
accommodate a larger DG facility.
– Direct Transfer Trip (DTT) schemes
– Directionalized overcurrent protection
– Block close schemes
– Reverse power schemes
• Metering and any monitoring/SCADA equipment and
associated communications circuits
22
Other Systems
• Smaller non-inverter systems
– Synchronous or induction machines
– May require same level of testing as larger systems
• Larger inverter-based systems
– Level of testing can vary
– Moderate levels may still allow inverters to provide
needed interconnection protection
– Higher levels may require additional interconnection
protection and correspondingly testing
23
Periodic Testing and Record Keeping
The interconnection system should be periodically tested
and maintained as stated in the DG Interconnection and
Operations Agreement between the utility and DG owner.

It is typically recommended
that periodic tests are
performed no less than every 5
years.

Done by DG owner with
notification to the utility
(utility personnel may witness
the testing).
24
Questions?
25
Power System Engineering, Inc.
Name: Jeffrey M. Triplett, P.E.
Direct: 740-568-9220
Thank You!
Mobile: 740-525-0070
Email: [email protected]
Website: www.powersystem.org
26